1. Field of the Invention.
This invention pertains to the treating of wells and more particularly to an improved perforation plugging element and the utilization of such elements for temporary closing of such perforations in the casing.
2. Description of the Prior Art.
It is common practice in completing oil and gas wells to set a string of pipe, known as casing, in the well and use cement around the outside of the casing to isolate the various formations penetrated by the well. To establish fluid communication between the hydrocarbon bearing formations and the interior of the casing, the casing and cement sheath are perforated.
At various times during the life of the well, it may be desirable to increase the production rate of hydrocarbons through treatment such as acidizing or hydraulic fracturing. If only a short, single pay zone in the well has been perforated, the treating fluid will flow into the pay zone where it is required. As the length of the perforated pay zone or the number of perforated pay zones increases, the placement of the fluid treatment in the regions of the pay zones where it is required becomes more difficult. For instance, the strata having the highest permeability will most likely consume the major portion of a given stimulation treatment leaving the least permeable strata virtually untreated. Therefore, techniques have been developed to divert the treating fluid from its path of least resistance so that the low permeability zones are also treated.
One technique for achieving diversion involves the use of downhole equipment such as packers. Although these devices are effective, they are quite expensive due to the involvement of associated workover equipment required during the tubing-packer manipulations. Additionally, mechanical reliability tends to decrease as the depth of the well increases.
As a result, considerable effort has been devoted to the development of alternative diverting methods. One of the most popular and widely used diverting techniques over the past 20 years has been the use of small rubber-coated balls, known as ball sealers, to seal off the perforations inside the casing.
These ball sealers are pumped into the wellbore along with the formation treating fluid. The balls are carried down the wellbore and on to the perforations by the flow of the fluid through the perforations into the formation. The balls seat upon the perforations and are held there by the pressure differential across the perforation.
The major advantages of utilizing ball sealers as a diverting agent are: easy to use, positive shutoff, independent of the formation, and non-damaging to the well. The ball sealers are simply injected at the surface and transported by the treating fluid. Other than a ball injector, no special or additional treating equipment is required. The ball sealers are designed to have a solid core which resists extrusion into or through the perforation. Therefore, the ball sealers will not penetrate the formation and permanently damage the flow characteristics of the well.
Several requirements are repeatedly applied to ball sealers as they are normally utilized today. First, the ball sealers must be chemically inert in the environment to which they are exposed. Second, they must seal effectively, yet not extrude into the perforations. Third, the ball sealer must release from the perforations when the pressure differential into the formation is relieved. Fourth, the ball sealers are generally heavier than the wellbore fluid so that they will sink to the bottom of the well, and out of the way, upon completion of the treatment.
Although present-day ball sealer diverting techniques have met with considerable usage, there is abundant evidence which indicates that the ball sealers often do not perform effectively because only a fraction of the ball sealers injected actually seat on perforations. The present-day practice of using ball sealers having a density greater than the treating fluid yields a low and unpredictable seating efficiency highly dependent on the difference in density between the ball sealers and the fluid, the flow rate of the fluid through the perforations, and the number, spacing and orientation of the perforations. The net result is that the plugging of the desired number of perforations at the proper time during the treatment to effect the desired diversion is left completely to chance.
When these inefficiencies lead to treatment failures, it is generally believed that these failures result from insufficient flow being carried through the perforations, thereby allowing the balls to fall to the bottom of the well without achieving fluid diversion. Attempts to overcome this problem generally include pumping a quantity of balls which exceeds the number of perforations. Although this procedure can be helpful, it has not proven to be a satisfactory solution.